Traceable Polymeric Additives for Use in Subterranean Formations

ABSTRACT

Disclosed are traceable polymeric additives that comprise a tagging material and methods of using the traceable polymeric additives in subterranean applications, such as cementing. An embodiment discloses a well treatment composition comprising a base fluid and a traceable polymeric additive comprising a polymer and a tagging material.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a divisional application of U.S. patentapplication Ser. No. 14/412,112, filed Dec. 30, 2014, which was anational stage entry of International Application No. PCT/US2013/071495,filed Nov. 22, 2013, the entire disclosures of which are incorporatedherein by reference.

BACKGROUND

Embodiments are directed to polymeric additives for use in subterraneanformations and, in certain embodiments, to traceable polymeric additivesthat comprise a tagging material and methods of using the traceablepolymeric additives in subterranean applications, such as cementing.

Cement compositions may be used in a variety of subterraneanapplications. For example, cement compositions may be used in primarycementing operations whereby pipe strings, such as casing and liners,may be cemented in wellbores. In a typical primary cementing operation,a cement composition may be pumped into an annulus between the exteriorsurface of the pipe string disposed therein and the walls of thewellbore (or a larger conduit in the wellbore). The cement compositionmay set in the annulus, thereby forming an annular sheath of hardened,substantially impermeable material (e.g., a cement sheath) that maysupport and position the pipe string in the wellbore and may bond theexterior surface of the pipe string to the wellbore walls (or to thelarger conduit). Among other things, the cement sheath surrounding thepipe string should function to prevent the migration of fluids in theannulus, as well as protecting the pipe string from corrosion. Cementcompositions may also be used in remedial cementing methods, such as inthe placement of a cement plug or in squeeze cementing for sealing voidsin a pipe string, cement sheath, gravel pack, subterranean formation,and the like.

Polymeric additives, such as elastomers, may be included in a cementcomposition. Among other reasons, elastomers may be included in a cementcomposition to improve the mechanical properties of the set cementcomposition. For example, elastomers may be included in a cementcomposition to improve the elasticity and ductility of the set cementcomposition, thereby potentially counteracting possible stresses thatmay be encountered by the cement composition in a wellbore. In someinstances, elastomers that swell upon contact with water and/or oil maybe used. These swellable elastomers may help maintain zonal isolation,for example, by swelling when contacted by oil and/or water to sealcracks in the cement sheath and/or micro-annulus between the cementsheath and the pipe string or formation that may be created.

When elastomers are included in a cement composition, the elastomers maytend to float, which could leave certain areas of the cement compositionwith little or no elastomer. As a result, the cement composition may nothave a uniform density distribution when introduced into the formation,resulting in a potential for the design specifications of the cementcomposition to not be met. Therefore, it can be desirable to determinethe location of the polymeric additives such as elastomers in the cementcomposition.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 is a schematic illustration of a system for the preparation anddelivery of a cement composition comprising a traceable polymericadditive to a wellbore in accordance with certain embodiments.

FIG. 2 is a schematic illustration of surface equipment that may be usedin the placement of a cement composition comprising a traceablepolymeric additive in a wellbore in accordance with certain embodiments.

FIG. 3 is a schematic illustration of the placement of a cementcomposition comprising a traceable polymeric additive into a wellboreannulus in accordance with certain embodiments.

FIG. 4 is a schematic illustration of a spacer fluid comprising atraceable polymeric additive concentrated in a wellbore annulus inaccordance with certain embodiments.

DESCRIPTION OF PREFERRED EMBODIMENTS

Embodiments are directed to polymeric additives for use in subterraneanformations and, in certain embodiments, to traceable polymeric additivesthat comprise a tagging material and methods of using the traceablepolymeric additives in subterranean applications, such as cementing. Inaccordance with present embodiments, the “polymeric additives” disclosedherein may be referred to as “traceable” because a tagging material(e.g., a thermal neutron absorbing material) may be included inpolymeric additives wherein the tagging material allows location of thepolymeric additives to be determined after placement into a wellbore. Byknowing their location, an operator may determine if the traceablepolymeric additives have segregated in the fluid in the wellbore,allowing remedial measures to be taken if desired. In addition tocementing, the traceable polymeric additives may be used in othersubterranean applications, such as the reduction of annular pressurebuildup.

In some embodiments, the traceable polymeric additives may be includedin a cement composition. An example of a cement composition may comprisehydraulic cement, a traceable polymeric additive, and water. Those ofordinary skill in the art will appreciate that embodiments of the cementcompositions generally should have a density suitable for a particularapplication. By way of example, embodiments of the cement compositionsmay have a density of about 4 pounds per gallon (“lb/gal”) to about 20lb/gal. Embodiments of the cement compositions may be foamed or unfoamedor may comprise other means to reduce their densities, such as hollowmicrospheres, low-density elastic beads, or other density-reducingadditives known in the art. In some embodiments, weighting agents may beused to increase the density of the cement composition. Those ofordinary skill in the art, with the benefit of this disclosure, willrecognize the appropriate density for a particular application.

Any of a variety of hydraulic cements suitable for use in subterraneancementing operations may be used in accordance with embodiments of thecement compositions. Suitable examples include hydraulic cements thatcomprise calcium, aluminum, silicon, oxygen and/or sulfur, which set andharden by reaction with water. Examples of such hydraulic cements,include, but are not limited to, Portland cements, pozzolana cements,gypsum cements, high-alumina-content cements, slag cements, silicacements, and combinations thereof. In certain embodiments, the hydrauliccement may comprise a Portland cement. In some embodiments, the Portlandcements are classified as Classes A, C, H, or G cements according toAmerican Petroleum Institute, API Specification for Materials andTesting for Well Cements, API Specification 10, Fifth Ed., Jul. 1, 1990.In addition, in some embodiments, the hydraulic cement may includecements classified as ASTM Type I, II, or III.

A traceable polymeric additive may be included in embodiments of thecement compositions. The traceable polymeric additives may be acomposite material that comprises a polymer and a tagging material. Thetraceable polymeric additive may be included in the cement compositionto improve the mechanical properties of the cement composition aftersetting. For example, the traceable polymeric additive may improve theelasticity and ductility of the set cement composition, therebypotentially counteracting possible stresses that may be encountered bythe cement composition in a wellbore. In addition, by inclusion of thetagging material, the polymeric additives may be traceable allowingdetection in the wellbore. Accordingly, any potential issues withsegregation may be detected and addressed by remedial measures ifneeded.

A wide variety of polymers may be employed, including homopolymers,copolymers, interpolymers, and mixtures of polymers. In someembodiments, the polymer may be a swellable polymer. As used herein, apolymer is characterized as swellable when it swells upon contact withoil and/or aqueous fluids (e.g., water). By way of example, the polymermay be an oil-swellable polymer that it swells upon contact with any ofa variety of oils, such as crude oil, diesel oil, kerosene and the like,as well as, oil-based fluids and gas or liquid hydrocarbons located insubterranean formations. By way of further example, the elastomer may bea water-swellable polymer that swells upon contact with aqueous fluids,such as fresh water, salt water and the like, as well as, water-basedfluids and aqueous fluids located in subterranean formations. Amongother things, use of a swellable polymer in embodiments of the cementcompositions may help maintain zonal isolation, for example, by swellingwhen contacted by oil and/or aqueous fluids to seal cracks in the cementsheath and/or micro-annulus between the cement sheath and the pipestring or formation that may be created.

Swellable polymers suitable for use in embodiments of the cementcompositions may generally swell by up to about 50% or more of theiroriginal size at the surface. Under downhole conditions, this swellingmay be more (or less) dependent on the conditions presented. Forexample, the swelling may be about 10% or more at downhole conditions.In some embodiments, the swelling may be up about 50% or more underdownhole conditions. However, as those of ordinary skill in the art,with the benefit of this disclosure, will appreciate, the actualswelling when the swellable polymer is included in a cement compositionmay vary, for example, based on the concentration of the swellablepolymer included in the cement composition and the amount of oil and/oraqueous fluid present, among other factors.

In some embodiments, the polymer may be an elastomer. A wide variety ofelastomers may be employed, including natural, synthetic, thermoplastic,and thermosetting elastomers. In particular embodiments, the elastomermay be swellable. Some specific examples of swellable elastomersinclude, but are not limited to, natural rubber, acrylate butadienerubber, polyacrylate rubber, isoprene rubber, choloroprene rubber, butylrubber (IIR), brominated butyl rubber (BIIR), chlorinated butyl rubber(CIIR), chlorinated polyethylene rubber (CM/CPE), neoprene rubber (CR),styrene butadiene copolymer rubber (SBR), sulphonated polyethylene(CSM), ethylene acrylate rubber (EAM/AEM), epichlorohydrin ethyleneoxide copolymer rubber (CO, ECO), ethylene-propylene rubber (EPM andEDPM), ethylene-propylene-diene terpolymer rubber (EPT), ethylene vinylacetate copolymer, fluorosilicone rubbers (FVMQ), silicone rubbers(VMQ), poly 2,2,1-bicyclo heptene (polynorborneane), and alkylstyrene.One example of a suitable swellable elastomer comprises a blockcopolymer of styrene-butadiene rubber. Examples of suitable elastomersthat swell in contact with oil include, but are not limited to, nitrilerubber (NBR), hydrogenated nitrile rubber (HNBR, HNS), fluoro rubbers(FKM), perfluoro rubbers (FFKM), tetrafluorethylene/propylene (TFE/P),and isobutylene maleic anhydride.

In some embodiments, the elastomer may be water-swellable.Water-swellable elastomers may, for example, be derived from monomerswhich may include butadiene, chloroprene or isoprene copolymerized withmonomers which produce polymers that are water-swellable. Additionalmonomers may include open-chain conjugated dienes having from 5 to 8carbon atoms, such as 2,3-dimethylbutadiene, 1,4-dimethylbutadiene, andpiperylene. In some embodiments, the monomers may be copolymerized witha monomer which will render the elastomer water swellable, such asunsaturated polymerizable carboxylic acids (e.g., maleic cid, fumaricacid, etc.), sulfonic acids, and phosphoric acids. Polymerizableunsaturated molecules which contain more than one sulfonic, sulfate,phosphoric, or phosphate group may also be suitable for copolymerizationwith the monomers. Elastomeric copolymers containing monomers havingwater susceptible groups such as amides, amines and hydroxyl may also beused in some embodiments. Examples of such monomers may include, withoutlimitation, furnaramide, acrylamide, and methacrylamide. Copolymers ofany combination of the above monomers with monomers containingconjugated unsaturation may be obtained by copolymerizing theelastomeric engendering monomer with monomers that may be reacted toprovide water swellability. Such polymers may include copolymers ofdiene monomers with acrylonitrile, acrylate esters and amides,methacrylate esters and amides, and maleic anhydride. These copolymersmay be hydrolyzed to provide copolymers containing unsaturated chemicalunits and carboxylic acid units. Other reactions to provide suitableelastomers may include reactions on polymers such as hydrolysis ofcopolymers of vinyl acetate to give hydroxyl groups, ammonolysis ofester groups to give amide groups, and sulfonation to give elastomerswhich have sulfonic acid groups.

Combinations of swellable elastomers may also be used. Other elastomersthat behave in a similar fashion with respect to oil or aqueous fluidsalso may be suitable. Those of ordinary skill in the art, with thebenefit of this disclosure, will be able to select an appropriateswellable elastomer for use in the example cement compositions based ona variety of factors, including the application in which the compositionwill be used and the desired swelling characteristics.

In some embodiments, the polymer may be a water-swellable polymer. Byway of example, the water-soluble polymer may include any of a varietyof polymers that swell upon contact with water. Some specific examplesof water-swellable polymers include, but are not limited to,super-absorbent polymers (such as polymethacrylate and polyacrylamide)and non-soluble acrylic polymers (such as starch-polyacrylate acid graftcopolymer and salts thereof), polyethylene oxide polymers, carboxymethylcellulose type polymers, poly(acrylic acid) and salts thereof,poly(acrylic-co-acrylamide) and salts thereof, graft-poly(ethyleneoxide) of poly(acrylic acid) and salts thereof, poly(2-hydroxyethylmethacrylate), poly(2-hydroxypropyl methacrylate), polyvinyl alcoholcyclic acid anhydride graft copolymer, isobutylene maleic anhydride,vinylacetate-acrylate copolymer, and starch-polyacrylonitrile graftcopolymers. Combinations of water-swellable polymers may also besuitable. Other polymers that behave in a similar fashion with respectto aqueous fluids also may be suitable. Those of ordinary skill in theart, with the benefit of this disclosure, will be able to select anappropriate water-swellable polymer based on a variety of factors,including the application in which the composition will be used and thedesired swelling characteristics.

Embodiments of the polymers may be dual oil/water swellable, in that thepolymer may comprise a combination or mixture of both oil-swellable andwater-swellable materials. A polymer is characterized as “dualoil/water-swellable” when it swells upon contact with oil and alsoswells upon contact with aqueous fluids. In accordance with presentembodiments, the oil-swellable material and/or the water-swellablematerial may comprise an elastomer. By way of example, the swellablepolymer may comprise an ethylene-propylene polymer (e.g.,ethylene-propylene copolymer rubber or ethylene-propylene-dieneterpolymer rubber) and bentonite. By way of further example, theswellable polymer may comprise a butyl rubber and sodium bentonite.

Tagging materials may be included in the traceable polymeric additives.Inclusion of the tagging material may allow the use of typical wellborelogging devices to determine the location of the traceable polymericadditives in the wellbore. In particular embodiments, the taggingmaterial may be dispersed in the polymer. In alternative embodiments,the tagging material may be at least partially coated on the polymer.For example, the tagging material may be included in a coating on thepolymer, such as a resin coating.

Suitable tagging materials may comprise relatively inert materialsand/or also materials that are thermal neutron absorbing materials. Insome embodiments, the tagging materials may be inert to the chemical andphysical properties of the cement composition. In some embodiments,these tagging materials should cause no significant changes in theconventional, desirable cement properties of cement composition, suchproperties may include density, rheology, pumping time, fluid loss,static gel strength, permeability, etc. Additionally, materials whichthemselves are not environmentally destructive may be used in particularembodiments.

Thermal neutron absorbing materials may comprise any element which has athermal neutron absorbing capability of a magnitude such thatdifferences in the backscattered thermal neutrons before and after thetraceable polymeric additive is introduced into a well bore can bedetected. Example embodiments may comprise thermal neutron absorbingmaterials for use with neutron logging devices, however, taggingmaterials may comprise a variety of materials including those known inthe art. Examples of suitable thermal neutron absorbing materialsinclude cadmium, boron, gadolinium, iridium, and mixtures thereof. Theboron may comprise boron carbide, boron nitride, boric acid, high boronconcentrated glass, zinc borate, borax, and mixtures thereof. Thegadolinium may comprise gadolinium oxide, gadolinium hydroxide,gadolinium acetate, high gadolinium concentrated glass, and mixturesthereof.

The amount of the tagging material used in embodiments of the traceablepolymeric additives generally may depend on a number of factors,including the particular elastomer, the particular tagging material, andcost, among others. In certain embodiments, the traceable polymericadditives may have a weight ratio of the elastomer to the taggingmaterial of about 99:1 to about 0.1:1 and, alternatively, a weight ratioof about 3:1 to about 1:1.

The traceable polymeric additive may be added to embodiments of thecement composition by dry blending with the hydraulic cement before theaddition of the water, by mixing with the water to be added to thehydraulic cement, or by mixing with the cement composition consecutivelywith or after the addition of the water. Moreover, the traceablepolymeric additive may be included in embodiments of the cementcompositions in an amount desired for a particular application. In someembodiments, the traceable polymeric additive may be present in anamount of about 0.1% to about 100% by weight of the hydraulic cement(“bwoc”) (e.g., about 1%, about 5%, about 10%, about 20%, about 30%,about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, etc.).In certain embodiments, the traceable polymeric additive may be presentin an amount of about 1% to about 30% bwoc, in an amount of about 5% toabout 25% bwoc, or in an amount of about 15% to about 20% bwoc. Inparticular embodiments, the tagging material may be present in an amountof about 5% bwoc or less.

In addition, the traceable polymeric additives generally may be inparticulate form. As used herein, the term “particulate” refers tomaterials in solid state having a well-defined physical shape as well asthose with irregular geometries, including any particulates elastomershaving the physical shape of platelets, shavings, fibers, flakes,ribbons, rods, strips, spheroids, hollow beads, toroids, pellets,tablets, or any other physical shape. In some embodiments, the traceablepolymeric additives may have a particle size in the range of about 5microns to about 1,500 microns. In some embodiments, the traceablepolymeric additives may have a particle size in the range of about 20microns to about 500 microns. However, particle sizes outside thesedisclosed ranges may also be suitable for particular applications.

Other additives suitable for use in subterranean cementing operationsalso may be added to embodiments of the cement compositions as deemedappropriate by one of ordinary skill in the art. Examples of suchadditives include, but are not limited to, strength-retrogressionadditives, set accelerators, set retarders, weighting agents,lightweight additives, gas-generating additives, mechanical propertyenhancing additives, lost-circulation materials, dispersants, fluid losscontrol additives, defoaming agents, foaming agents, thixotropicadditives, and combinations thereof. Specific examples of these, andother, additives include silica (e.g., crystalline silica, amorphoussilica, fumed silica, etc.), salts, fibers, hydratable clays, shale(e.g., calcined shale, vitrified shale, etc.), microspheres,diatomaceous earth, natural pozzolan, resins, latex, combinationsthereof, and the like. Other optional additives may also be included,including, but not limited to, cement kiln dust, lime kiln dust, flyash, slag cement, shale, zeolite, metakaolin, pumice, perlite, lime,silica, rice husk ash, small-particle size cement, combinations thereof,and the like. A person having ordinary skill in the art, with thebenefit of this disclosure, will readily be able to determine the typeand amount of additive useful for a particular application and desiredresult.

Strength-retrogression additives may be included in embodiments of thecement composition to, for example, prevent the retrogression ofstrength after the cement composition has been allowed to developcompressive strength when the cement composition is exposed to hightemperatures. These additives may allow the cement compositions to formas intended, preventing cracks and premature failure of the cementitiouscomposition. Examples of suitable strength-retrogression additives mayinclude, but are not limited to, amorphous silica, coarse graincrystalline silica, fine grain crystalline silica, or a combinationthereof.

Set accelerators may be included in embodiments of the cementcompositions to, for example, increase the rate of setting reactions.Control of setting time may allow for the ability to adjust to well boreconditions or customize set times for individual jobs. Examples ofsuitable set accelerators may include, but are not limited to, aluminumsulfate, alums, calcium chloride, calcium sulfate, gypsum-hemihydrate,sodium aluminate, sodium carbonate, sodium chloride, sodium silicate,sodium sulfate, ferric chloride, or a combination thereof.

Set retarders may be included in embodiments of the cement compositionsto, for example, increase the thickening time of the cementcompositions. Examples of suitable set retarders include, but are notlimited to, ammonium, alkali metals, alkaline earth metals, borax, metalsalts of calcium lignosulfonate, carboxymethyl hydroxyethyl cellulose,sulfoalkylated lignins, hydroxycarboxy acids, copolymers of2-acrylamido-2-methylpropane sulfonic acid salt and acrylic acid ormaleic acid, saturated salt, or a combination thereof. One example of asuitable sulfoalkylated lignin comprises a sulfomethylated lignin.

Weighting agents are typically materials that weigh more than water andmay be used to increase the density of a cement composition. By way ofexample, weighting agents may have a specific gravity of about 2 orhigher (e.g., about 2, about 4, etc.). Examples of weighting agents thatmay be used include, but are not limited to, hematite, hausmannite, andbarite, and combinations thereof. Specific examples of suitableweighting agents include HI-DENSE® weighting agent, available fromHalliburton Energy Services, Inc.

Lightweight additives may be included in embodiments of the cementcompositions to, for example, decrease the density of the cementcompositions. Examples of suitable lightweight additives include, butare not limited to, bentonite, coal, diatomaceous earth, expandedperlite, fly ash, gilsonite, hollow microspheres, low-density elasticbeads, nitrogen, pozzolan-bentonite, sodium silicate, combinationsthereof, or other lightweight additives known in the art.

Gas-generating additives may be included in embodiments of the cementcompositions to release gas at a predetermined time, which may bebeneficial to prevent gas migration from the formation through thecement composition before it hardens. The generated gas may combine withor inhibit the permeation of the cement composition by formation gas.Examples of suitable gas-generating additives include, but are notlimited to, metal particles (e.g., aluminum powder) that react with analkaline solution to generate a gas.

Mechanical-property-enhancing additives may be included in embodimentsof the cement compositions to, for example, ensure adequate compressivestrength and long-term structural integrity. These properties can beaffected by the strains, stresses, temperature, pressure, and impacteffects from a subterranean environment. Examples of mechanical propertyenhancing additives include, but are not limited to, carbon fibers,glass fibers, metal fibers, mineral fibers, silica fibers, polymericelastomers, and latexes.

Lost-circulation materials may be included in embodiments of the cementcompositions to, for example, help prevent the loss of fluid circulationinto the subterranean formation. Examples of lost-circulation materialsinclude but are not limited to, cedar bark, shredded cane stalks,mineral fiber, mica flakes, cellophane, calcium carbonate, groundrubber, polymeric materials, pieces of plastic, grounded marble, wood,nut hulls, formica, corncobs, and cotton hulls.

Dispersants may be included in embodiments of the cement compositions.Where present, the dispersant should act, among other things, to controlthe rheology of the cement composition. While a variety of dispersantsknown to those skilled in the art may be used in certain embodiments,examples of suitable dispersants include naphthalene sulfonic acidcondensate with formaldehyde; acetone, formaldehyde, and sulfitecondensate; melamine sulfonate condensed with formaldehyde; anycombination thereof.

Fluid-loss-control additives may be included in embodiments of thecement compositions to, for example, decrease the volume of fluid thatis lost to the subterranean formation. Properties of the cementcompositions may be significantly influenced by their water content. Theloss of fluid can subject the cement compositions to degradation orcomplete failure of design properties. Examples of suitablefluid-loss-control additives include, but not limited to, certainpolymers, such as hydroxyethyl cellulose, carboxymethylhydroxyethylcellulose, copolymers of 2-acrylamido-2-methylpropanesulfonic acid andacrylamide or N,N-dimethylacrylamide, and graft copolymers comprising abackbone of lignin or lignite and pendant groups comprising at least onemember selected from the group consisting of2-acrylamido-2-methylpropanesulfonic acid, acrylonitrile, andN,N-dimethylacrylamide.

Defoaming additives may be included in embodiments of the cementcompositions to, for example, reduce tendency for the cement compositionto foam during mixing and pumping of the cement compositions. Examplesof suitable defoaming additives include, but are not limited to, polyolsilicone compounds. Suitable defoaming additives are available fromHalliburton Energy Services, Inc., under the product name D-AIR™defoamers.

Foaming additives (e.g., foaming surfactants) may be included inembodiments to, for example, facilitate foaming and/or stabilize theresultant foam formed therewith. Examples of suitable foaming additivesinclude, but are not limited to: mixtures of an ammonium salt of analkyl ether sulfate, a cocoamidopropyl betaine surfactant, acocoamidopropyl dimethylamine oxide surfactant, sodium chloride, andwater; mixtures of an ammonium salt of an alkyl ether sulfatesurfactant, a cocoamidopropyl hydroxysultaine surfactant, acocoamidopropyl dimethylamine oxide surfactant, sodium chloride, andwater; hydrolyzed keratin; mixtures of an ethoxylated alcohol ethersulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant,and an alkyl or alkene dimethylamine oxide surfactant; aqueous solutionsof an alpha-olefinic sulfonate surfactant and a betaine surfactant; andcombinations thereof. An example of a suitable foaming additive isZONESEALANT™ 2000 agent, available from Halliburton Energy Services,Houston, Tex.

Thixotropic additives may be included in embodiments of the cementcompositions to, for example, provide a cement composition that can bepumpable as a thin or low viscosity fluid, but when allowed to remainquiescent attains a relatively high viscosity. Among other things,thixotropic additives may be used to help control free water, createrapid gelation as the slurry sets, combat lost circulation, prevent“fallback” in annular column, and minimize gas migration. Examples ofsuitable thixotropic additives include, but are not limited to, gypsum,water soluble carboxyalkyl, hydroxyalkyl, mixed carboxyalkylhydroxyalkyl either of cellulose, polyvalent metal salts, zirconiumoxychloride with hydroxyethyl cellulose, or a combination thereof.

The cement compositions comprising hydraulic cement, a traceablepolymeric additive, and water may be used in a variety of cementingapplications. In some embodiments, a method of the present invention maycomprise providing a cement composition comprising hydraulic cement, atraceable polymeric additive, and water; and allowing the cementcomposition to set. As described above, the traceable polymeric additivemay comprise an elastomer and a tagging material. As will beappreciated, the cement composition may be allowed to set in anysuitable location where it may be desired for the cement composition toset into a hardened mass. By way of example, the cement composition maybe allowed to set in a variety of locations, both above and belowground.

Additionally, embodiments of the cement compositions may be used in avariety of subterranean operations, including primary and remedialcementing. In some embodiments, a cement composition may be providedthat comprises hydraulic cement, a traceable polymeric additive, andwater. The cement composition may be introduced into a subterraneanformation and allowed to set therein. As used herein, introducing thecement composition into a subterranean formation includes introductioninto any portion of the subterranean formation, including, withoutlimitation, into a wellbore drilled into the subterranean formation,into a near wellbore region surrounding the wellbore, or into both. Insome embodiments, a wellbore log (e.g., a cement bond log) may beprepared that may show where the tagging materials are located in thewellbore. This log can allow operators to determine whether segregationof the tagging materials in the wellbore has occurred.

In primary cementing embodiments, for example, the cement compositionmay be introduced into an annular space between a conduit located in awellbore and the walls of a wellbore (and/or a larger conduit in thewellbore), wherein the wellbore penetrates the subterranean formation.The cement composition may be allowed to set in the annular space toform an annular sheath of hardened cement. The cement composition mayform a barrier that prevents the migration of fluids in the wellbore.The cement composition may also, for example, support the conduit in thewellbore.

In remedial cementing embodiments, a cement composition may be used, forexample, in squeeze-cementing operations or in the placement of cementplugs. By way of example, the cement composition may be placed in awellbore to plug an opening (e.g., a void or crack) in the formation, ina gravel pack, in the conduit, in the cement sheath, and/or between thecement sheath and the conduit (e.g., a microannulus).

While the preceding discussion is directed to the use of a traceablepolymeric additive in cementing methods, those of ordinary skill in theart will appreciate that the traceable polymeric additives may also beused in a variety of different subterranean treatments, includingdrilling fluids, completing fluids, stimulation fluids, spacer fluids,and well clean-up fluids. The traceable polymeric additives may beincluded in these well treatment fluids in any suitable amount for aparticular application, including from about 1% to about 60% by volumeof the well treatment fluid. In accordance with one embodiment, atraceable polymeric additive may be included in a spacer fluid. Forexample, a spacer fluid may be placed between two fluids contained in orto be pumped within a wellbore. Examples of fluids between which spacerfluids are utilized include between cement compositions, and drillingfluids, between different drilling fluids during drilling fluid changeouts and between drilling fluids and completion brines. Among otherthings, spacer fluids may be used to enhance drilling fluid and filtercake removal from the walls of wellbores, to enhance displacementefficiency and to physically separate chemically incompatible fluids.For example, a cement composition and a drilling fluid may be separatedby a spacer fluid when the cement composition is placed in the wellbore.In accordance with embodiments of the present invention, the spacerfluid may prevent, or at least partially reduce, intermixing of thecement composition and the drilling fluid and may facilitate the removalof filter cake and gelled drilling fluid from the walls of the wellboreduring displacement of the drilling fluid by the cement composition. Inaccordance with another embodiment, the traceable polymeric additive maybe included in a drilling fluid. By way of example, a method maycomprise using a drill bit to enlarge a wellbore; and circulating adrilling fluid that comprises a traceable polymeric additive past thedrill bit to remove cuttings.

As will be appreciated by those of ordinary skill in the art,embodiments of the traceable polymeric additives may be used to controllost circulation. In some embodiments, lost circulation zones may beencountered into which drilling fluid (or other treatment fluid)circulation can be lost. Lost circulation zones include zones of asubterranean formation containing fractures or other openings into whichtreatment fluids may be lost. As a result, the well treatment (e.g.,drilling) typically must be terminated with the implementation ofremedial procedures, for example. In accordance with embodiments, thetraceable polymeric additives may be introduced into a wellborepenetrating the subterranean formation to seal the lost circulationzones and prevent the uncontrolled flow of fluids into or out of thelost circulation zones, e.g., lost drilling fluid circulation,crossflows, underground blow-outs and the like. In embodiments, atreatment fluid comprising the traceable polymeric additives may beintroduced into the lost circulation zone. In an embodiment, thetreatment fluid may be pumped through one or more openings at the end ofthe string of drill pipe. For example, the treatment fluid can be pumpedthrough the drill bit. In addition to drilling fluids, embodiments mayalso be used to control lost circulation problems encountered with otherfluids, for example, spacer fluids, completion fluids (e.g., completionbrines), fracturing fluids, and cement compositions that may be placedinto a well bore.

In some embodiments, the traceable elastomeric particles may be used tocombat annular pressure buildup. Hydrocarbons (e.g., oil, gas, etc.)that may be produced at the surface may be at elevated temperatures asthey flow up through the casing/tubing, thus transferring heat throughthe pipe string into the wellbore. This may cause fluids in the wellboreannulus to expand. For example, spacer fluids remaining in the wellboreannulus above the cement sheath may heat and expand. Such an expansionmay cause an increase in pressure within the wellbore annulus, which iscommonly referred to as “annular pressure buildup.” Annulus pressurebuildup typically occurs when annular volume is fixed. For instance, thewellbore annulus may be closed (e.g., trapped) to isolate fluids in theannulus from outside the annulus. Closing the wellbore annulus may occurnear the end of the cementing operation after well completion fluidssuch as spacer fluids and cement compositions may be in place. By way ofexample, the wellbore annulus may be closed by closing a valve,energizing a seal, and the like. However, if a fluid is trapped in theclosed wellbore annulus experiences a temperature increase, a largepressure increase may be expected because the volume in the annulus isfixed. In some instances, this pressure increase may cause damage to thewellbore, such as damage to the cement sheath, casing, tubulars, orother equipment in the wellbore.

To alleviate problems with annular pressure buildup, the traceableelastomeric particles may be included in a fluid (e.g., a spacer fluid)that is to be left in the wellbore. For example, the fluid comprisingthe traceable elastomeric particles may become trapped in a wellboreannulus. Embodiments of the traceable elastomeric particles shouldreduce in volume when exposed to compressive forces at elevatedtemperatures when trapped in the wellbore annulus. When the compressiveforce is released, embodiments of the traceable elastomeric particlesmay be capable of rebounding to their original shape and volume andtherefore may be reusable for subsequent instances of annular pressurebuildup. In some instances, the compressive force may be generated byexpansion of the fluid or another fluid trapped in the wellbore annulusdue, for example, to a temperature rise. In some embodiments,hydrocarbon production in the wellbore may cause an increase in annulartemperature thus causing expansion of the treatment fluid or anothertreatment fluid in the wellbore with the resultant compressive force.Without being limited by theory, it is believed that reduction in volumeof the traceable elastomeric particles should provide an amount ofexpansion volume in the wellbore annulus, thus decreasing any potentialpressure rise due to the compressive force.

Additional embodiments may include detecting the subterranean locationof the traceable polymeric additives after the additives have beenintroduced into the wellbore, for example, in a cement composition,spacer fluid, or other fluid placed into the wellbore. In someembodiments, a log may be run in the wellbore that can detect thelocation of the traceable. In some embodiments, the log may be a neutronlog. Running the neutron log may include emitting fast neutrons into thewellbore. Conventional dual-spacing neutron tools (commonly referred toas DSN tools) are well known to those skilled in the art and have beenutilized heretofore for running neutron logs of subterranean formations.Such tools commonly include a neutron source for emitting fast neutrons,a long spacing thermal neutron detector and a short spacing thermalneutron detector. The DSN neutron tool or another tool containing asource from which fast neutrons are emitted may be lowered in thewellbore whereby the fast neutrons interact with elements in the welland are thermalized thereby. The thermal neutrons produced arebackscattered in the well and are detected by a thermal neutron detectorin the tool. The detector generates a count representative of thedetected thermal neutrons over one or more selected longitudinalsubterranean intervals in the wellbore, i.e., the intervals in thewellbore where it is expected that traceable polymeric additives will belocated after a treatment is performed in the well.

The subterranean locations of the traceable polymeric additives may bedetermined based on the differences in the count generated after theirintroduction and a count representative of the one or more subterraneanintervals in the well before their introduction. That is, because thetagging material in the traceable polymeric additives absorbs some ofthe thermal neutrons as they are generated in the wellbore after theirintroduction, a comparison of the before and after counts correlatedwith the locations where the counts were generated indicates thesubterranean locations of the traceable polymeric additives.

A thermal neutron count over the locations of interest in a wellborebefore introduction of the traceable polymeric additives may beavailable as a result of the performance of previous treatments therein,etc. If not, a before introduction count may be determined prior tointroducing the traceable polymeric additives into the wellbore. Thatis, a tool containing a fast neutron source may be lowered in thewellbore whereby the fast neutrons interact with elements in thewellbore and are thermalized. The thermal neutrons produced andbackscattered in the wellbore may be detected by a thermal neutrondetector as described above, and a count representative of the detectedthermal neutrons over the one or more selected subterranean intervals inthe wellbore may be produced.

An embodiment discloses a method of well treatment. The method maycomprise introducing a fluid comprising a traceable polymeric additiveinto a wellbore, wherein the traceable polymeric additive comprises apolymer and a tagging material.

An embodiment discloses a well treatment fluid comprising: a base fluid;and a traceable polymeric additive comprising a polymer and a taggingmaterial.

An embodiment discloses a well treatment system comprising: a treatmentfluid for introduction into a well bore, wherein the treatment fluidcomprises a base fluid and a traceable polymeric additive comprising apolymer and a tagging material; and a logging tool for running a neutronlog in the wellbore.

Example methods of using the traceable elastomeric particles will now bedescribed in more detail with reference to FIGS. 1-4. FIG. 1 illustratesa system 5 for preparation of a cement composition comprising hydrauliccement, a traceable polymeric additive, and water and delivery of thecomposition to a wellbore in accordance with certain embodiments. Asshown, the cement composition may be mixed in mixing equipment 10, suchas a jet mixer, re-circulating mixer, or a batch mixer, for example, andthen pumped via pumping equipment 15 to the wellbore. In someembodiments, the mixing equipment 10 and the pumping equipment 15 may bedisposed on one or more cement trucks as will be apparent to those ofordinary skill in the art. In some embodiments, a jet mixer may be used,for example, to continuously mix a dry blend comprising the hydrauliccement and traceable polymeric additives, for example, with the water asit is being pumped to the wellbore.

An example technique for placing a cement composition into asubterranean formation will now be described with reference to FIGS. 2and 3. FIG. 2 illustrates surface equipment 20 that may be used inplacement of a cement composition in accordance with certainembodiments. It should be noted that while FIG. 2 generally depicts aland-based operation, those skilled in the art will readily recognizethat the principles described herein are equally applicable to subseaoperations that employ floating or sea-based platforms and rigs, withoutdeparting from the scope of the disclosure. As illustrated by FIG. 2,the surface equipment 20 may include a cementing unit 25, which mayinclude one or more cement trucks. The cementing unit 25 may includemixing equipment 10 and pumping equipment 15 (e.g., FIG. 1) as will beapparent to those of ordinary skill in the art. The cementing unit 25may pump a cement composition 30, which may comprise hydraulic cement, atraceable polymeric additive (e.g., 40 on FIG. 3), and water, through afeed pipe 35 and to a cementing head 36 which conveys the cementcomposition 30 downhole.

Turning now to FIG. 3, the cement composition 30, which may comprise thetraceable polymeric additive 40, may be placed into a subterraneanformation 45 in accordance with example embodiments. As illustrated, awellbore 50 may be drilled into one or more subterranean formations 45.While the wellbore 50 is shown extending generally vertically into theone or more subterranean formation 45, the principles described hereinare also applicable to wellbores that extend at an angle through the oneor more subterranean formations 45, such as horizontal and slantedwellbores. As illustrated, the wellbore 50 comprises walls 55. In theillustrated embodiment, a surface casing 60 has been inserted into thewellbore 50. The surface casing 60 may be cemented to the walls 55 ofthe wellbore 50 by cement sheath 65. In the illustrated embodiment, oneor more additional conduits (e.g., intermediate casing, productioncasing, liners, etc.), shown here as casing 70 may also be disposed inthe wellbore 50. As illustrated, there is a wellbore annulus 75 formedbetween the casing 70 and the walls 55 of the wellbore 50 and/or thesurface casing 60. One or more centralizers 80 may be attached to thecasing 70, for example, to centralize the casing 70 in the wellbore 50prior to and during the cementing operation.

With continued reference to FIG. 3, the cement composition 30 may bepumped down the interior of the casing 70. The cement composition 30 maybe allowed to flow down the interior of the casing 70 through the casingshoe 85 at the bottom of the casing 70 and up around the casing 70 intothe wellbore annulus 75. The cement composition 30 may be allowed to setin the wellbore annulus 75, for example, to form a cement sheath thatsupports and positions the casing 70 in the wellbore 50. While notillustrated, other techniques may also be utilized for introduction ofthe cement composition 30. By way of example, reverse circulationtechniques may be used that include introducing the set-delayed cementcomposition 30 into the subterranean formation 20 by way of the wellboreannulus 75 instead of through the casing 70.

As it is introduced, the cement composition 30 may displace other fluids90, such as drilling fluids and/or spacer fluids that may be present inthe interior of the casing 70 and/or the wellbore annulus 75. At least aportion of the displaced fluids 90 may exit the wellbore annulus 75 viaa flow line 95 and be deposited, for example, in one or more retentionpits 100 (e.g., a mud pit), as shown on FIG. 2. Referring again to FIG.3, a bottom plug 105 may be introduced into the wellbore 50 ahead of thecement composition 30, for example, to separate the cement composition30 from the other fluids 90 that may be inside the casing 70 prior tocementing. After the bottom plug 105 reaches the landing collar 110, adiaphragm or other suitable device should rupture to allow the cementcomposition 30 through the bottom plug 105. In FIG. 3, the bottom plug105 is shown on the landing collar 110. In the illustrated embodiment, atop plug 115 may be introduced into the wellbore 50 behind the cementcomposition 30. The top plug 115 may separate the cement composition 30from a displacement fluid 120 and also push the cement composition 30through the bottom plug 105.

Referring now to FIG. 4, the traceable polymeric additive 40 is showndisposed in a spacer fluid 125 in wellbore annulus 75 in accordance withcertain embodiments. As previously described, the traceable polymericadditive 40 may be placed in a spacer fluid 125, for example, toalleviate potential problems with annular pressure buildup. Asillustrated, the spacer fluid 125 is shown disposed in the wellboreannulus 75 above a cement sheath 130. The wellbore annulus 75 is shownbetween the wellbore 50 and the casing 70. As previously described, thewellbore annulus 75 may be closed such that the spacer fluid 125 and thecement sheath 130 may be trapped therein, the wellbore annulus 75 havinga fixed volume. Hydrocarbon production may be initiated from thewellbore 55 at some point in time after the cementing operation iscomplete. As illustrated, apertures 135 in the cement sheath 130 mayallow hydrocarbons to flow from a producing zone 140 of the one or moresubterranean formations 45 up through the casing 70 and to a surface145, as illustrated by arrows 150. Production tubing 155 may be disposedin the casing 70 to produce a conduit for passage of the hydrocarbons.As previously mentioned, the hydrocarbons may be at elevatedtemperatures as they flow up through the casing 70 causing fluids, suchas the spacer fluid 125, to heat and expand. Such an expansion may causean undesirable increase in pressure within the wellbore annulus 75 whenthe volume is fixed, for example. At least a portion of the traceablepolymeric additive 40 in the spacer fluid 125 may collapse or reduce involume so as to desirably mitigate, or prevent, the pressure buildup.

The exemplary traceable polymeric additive 40 disclosed herein maydirectly or indirectly affect one or more components or pieces ofequipment associated with the preparation, delivery, recapture,recycling, reuse, and/or disposal of the disclosed traceable polymericadditive 40. For example, the traceable polymeric additive 40 maydirectly or indirectly affect one or more mixers, related mixingequipment 15, mud pits, storage facilities or units, compositionseparators, heat exchangers, sensors, gauges, pumps, compressors, andthe like used generate, store, monitor, regulate, and/or recondition theexemplary traceable polymeric additive 40 and fluids containing thesame. The disclosed traceable polymeric additive 40 may also directly orindirectly affect any transport or delivery equipment used to convey thetraceable polymeric additive 40 to a well site or downhole such as, forexample, any transport vessels, conduits, pipelines, trucks, tubulars,and/or pipes used to compositionally move the traceable polymericadditive 40 from one location to another, any pumps, compressors, ormotors (e.g., topside or downhole) used to drive the traceable polymericadditive 40, or fluids containing the same, into motion, any valves orrelated joints used to regulate the pressure or flow rate of thetraceable polymeric additive 40 (or fluids containing the same), and anysensors (i.e., pressure and temperature), gauges, and/or combinationsthereof, and the like. The disclosed traceable polymeric additive 40 mayalso directly or indirectly affect the various downhole equipment andtools that may come into contact with the traceable polymeric additive40 such as, but not limited to, wellbore casing 70, wellbore liner,completion string, insert strings, drill string, coiled tubing,slickline, wireline, drill pipe, drill collars, mud motors, downholemotors and/or pumps, cement pumps, surface-mounted motors and/or pumps,centralizers, turbolizers, scratchers, floats (e.g., shoes, collars,valves, etc.), logging tools and related telemetry equipment, actuators(e.g., electromechanical devices, hydromechanical devices, etc.),sliding sleeves, production sleeves, plugs, screens, filters, flowcontrol devices (e.g., inflow control devices, autonomous inflow controldevices, outflow control devices, etc.), couplings (e.g.,electro-hydraulic wet connect, dry connect, inductive coupler, etc.),control lines (e.g., electrical, fiber optic, hydraulic, etc.),surveillance lines, drill bits and reamers, sensors or distributedsensors, downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers, cement plugs, bridge plugs, and otherwellbore isolation devices, or components, and the like.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, the invention covers all combinations of all thoseembodiments. Furthermore, no limitations are intended to the details ofconstruction or design herein shown, other than as described in theclaims below. Also, the terms in the claims have their plain, ordinarymeaning unless otherwise explicitly and clearly defined by the patentee.It is therefore evident that the particular illustrative embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the present invention. Ifthere is any conflict in the usages of a word or term in thisspecification and one or more patent(s) or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

What is claimed is:
 1. A well treatment fluid comprising: a base fluid;and a traceable polymeric additive comprising a polymer and a taggingmaterial.
 2. The well treatment fluid of claim 1 wherein the taggingmaterial comprises at least one thermal neutron absorbing materialselected from the group consisting of cadmium, boron, gadolinium,iridium, boron carbide, boron nitride, boric acid, boron concentratedglass, zinc borate, borax, gadolinium oxide, gadolinium acetate,gadolinium concentrated glass, and any combination thereof.
 3. The welltreatment fluid of claim 1 wherein the polymer is swellable.
 4. The welltreatment fluid of claim 1 wherein the traceable polymeric additive isin particulate form.
 5. The well treatment fluid of claim 1 wherein atleast a portion of the tagging material is dispersed in the polymer orpresent in a coating on the polymer.
 6. The well treatment fluid ofclaim 1 further comprising a hydraulic cement and water.
 7. The welltreatment fluid of claim 6 wherein the traceable polymeric additive isincluded in the fluid in an amount of about 0.1% to about 100% by weightof the hydraulic cement.
 8. The well treatment fluid of claim 1 whereinthe polymer comprises at least one elastomer selected from the groupconsisting of natural rubber, acrylate butadiene rubber, polyacrylaterubber, isoprene rubber, choloroprene rubber, butyl rubber, brominatedbutyl rubber, chlorinated butyl rubber, chlorinated polyethylene rubber,neoprene rubber, styrene butadiene copolymer rubber, sulphonatedpolyethylene, ethylene acrylate rubber, epichlorohydrin ethylene oxidecopolymer rubber, ethylene-propylene rubber, ethylene-propylene-dieneterpolymer rubber, ethylene vinyl acetate copolymer, a fluorosiliconerubber, a silicone rubber, poly 2,2,1-bicyclo heptene (polynorborneane),alkylstyrene, a block copolymer of styrene-butadiene rubber, nitrilerubber, hydrogenated nitrile rubber, a fluoro rubber, a perfluororubber, a tetrafluorethylene/propylene, an isobutylene maleic anhydride,and any combination thereof.
 9. The well treatment fluid of claim 1wherein the polymer comprises at least one swellable polymer selectedfrom the group consisting of polymethacrylate, polyacrylamide, anon-soluble acrylic polymer, a starch-polyacrylate acid graft copolymer,polyethylene oxide polymer, a carboxymethyl cellulose type polymer,poly(acrylic acid), poly(acrylic-co-acrylamide), graft-poly(ethyleneoxide) of poly(acrylic acid), poly(2-hydroxyethyl methacrylate),poly(2-hydroxypropyl methacrylate), polyvinyl alcohol cyclic acidanhydride graft copolymer, isobutylene maleic anhydride,vinylacetate-acrylate copolymer, a starch-polyacrylonitrile graftcopolymer, and any combination thereof.
 10. A well treatment fluidcomprising: a base fluid; a traceable polymeric additive wherein thetraceable polymeric additive is particulate in form and comprises aswellable elastomer and a tagging material; wherein the tagging materialcomprises a thermal neutron absorbing material; wherein a weight ratioof the swellable elastomer to the tagging material is about 99:1 toabout 0.1:1; and wherein the swellable elastomer comprises at least onepolymer selected from the group consisting of a water swellable polymer,oil swellable polymer, dual oil and water swellable polymer, andcombinations thereof.
 11. The well treatment fluid of claim 10 whereinat least a portion of the tagging material is dispersed in the at leastone polymer.
 12. The well treatment fluid of claim 10 wherein at least aportion of the tagging material is present in a coating on the at leastone polymer.
 13. The well treatment fluid of claim 10 wherein thethermal neutron absorbing material comprises at least one materialselected from the group consisting of cadmium, boron, gadolinium,iridium, boron carbide, boron nitride, boric acid, boron concentratedglass, zinc borate, borax, gadolinium oxide, gadolinium acetate,gadolinium concentrated glass, and any combination thereof.
 14. The welltreatment fluid of claim 10 wherein the swellable elastomer comprises atleast one elastomer selected from the group consisting of naturalrubber, acrylate butadiene rubber, polyacrylate rubber, isoprene rubber,choloroprene rubber, butyl rubber, brominated butyl rubber, chlorinatedbutyl rubber, chlorinated polyethylene rubber, neoprene rubber, styrenebutadiene copolymer rubber, sulphonated polyethylene, ethylene acrylaterubber, epichlorohydrin ethylene oxide copolymer rubber,ethylene-propylene rubber, ethylene-propylene-diene terpolymer rubber,ethylene vinyl acetate copolymer, a fluorosilicone rubber, a siliconerubber, poly 2,2,1-bicyclo heptene (polynorborneane), alkylstyrene, ablock copolymer of styrene-butadiene rubber, nitrile rubber,hydrogenated nitrile rubber, a fluoro rubber, a perfluoro rubber, atetrafluorethylene/propylene, an isobutylene maleic anhydride, and anycombination thereof.
 15. The well treatment fluid of claim 10, whereinthe swellable elastomer comprises at least one swellable polymerselected from the group consisting of polymethacrylate, polyacrylamide,a non-soluble acrylic polymer, a starch-polyacrylate acid graftcopolymer, polyethylene oxide polymer, a carboxymethyl cellulose typepolymer, poly(acrylic acid), poly(acrylic-co-acrylamide),graft-poly(ethylene oxide) of poly(acrylic acid), poly(2-hydroxyethylmethacrylate), poly(2-hydroxypropyl methacrylate), polyvinyl alcoholcyclic acid anhydride graft copolymer, isobutylene maleic anhydride,vinylacetate-acrylate copolymer, a starch-polyacrylonitrile graftcopolymer, and any combination thereof.
 16. The well treatment fluid ofclaim 10 further comprising a hydraulic cement and water.
 17. The welltreatment fluid of claim 16 wherein the traceable polymeric additive isincluded in the well treatment fluid in an amount of about 0.1% to about100% by weight of the hydraulic cement.
 18. The well treatment fluid ofclaim 16 wherein the well treatment fluid comprises a density of about 4lb/gal to about 20 lb/gal.
 19. The well treatment fluid of claim 16wherein the traceable polymeric additive comprises a particle size in arange of about 20 microns to about 500 microns.
 20. The well treatmentfluid of claim 16 further comprising a dispersant.